For several years the United States Environmental Protection Agency (EPA) has required operators of fossil-fueled power plants, incinerators, metal smelters, and cement kilns to monitor levels of certain gaseous species and particulates that are released into the atmosphere. These species include sulfur oxides, nitrogen oxides, carbon monoxide, carbon dioxide and oxygen which generally exit the furnace through duct work leading to the furnace stack or chimney. There are also laws and regulations that set emission standards and provide penalties for operators who fail to meet those standards. Operators of these facilities must monitor emissions and often will add materials to the flue gas to reduce the level of emissions of the certain gaseous species. Typically, monitoring is done through the insertion of a probe capable of in-situ monitoring or by an extraction probe or sampling line into the flue gas at selected locations in the furnace. In order to analyze an extracted sample for its gaseous constituents, it is sometimes necessary to remove the particulates and transport the sample to a remote location suitable for the operation of gas analysis instrumentation.
The art has developed a variety of probes that are used to take samples of flue gas from a stack. Examples of these sampling systems are disclosed in U.S. Pat. No. 5,458,010. In a traditional extractive system a pump draws gas through heated probe from a gas stream moving within stack. The sample is then transported to a remote location through a heat-traced sample line for analysis. The probe and sample line are heated to about 250° F. to prevent condensation of the moisture or acid in the sample. Next, the sample is drawn through a “chiller” which lowers the sample temperature to approximately 35° F. The water vapor thus condenses and is drained away. The sample, now dry, is then reheated and transported through an analyzer which measures the constituents of interest.
A second general type of prior art sampling system uses a dilution probe. In this design, the rate of stack sample extraction is considerably smaller than is the case with the traditional system. Here, gas is drawn through a fine filter into a device known as a “sonic orifice” or “critical-flow orifice.” The sonic orifice is so called because it meters a constant volumetric flow provided that a substantial vacuum exists behind the orifice. Vacuum on the back side of the orifice is maintained by a venturi which is driven by a compressed air source. The venturi also serves to provide clean, dry dilution air which lowers the sample dew-point. The entire venturi/orifice assembly is constructed within a non-heated probe such that the dilution is accomplished at essentially stack temperature. The diluted sample is then sent to analyzer at approximately atmospheric pressure.
Temperature sensors are often provided in the probes used in the prior art sampling systems.
To control emission operators of fossil fuel burning furnaces may add ammonia, calcium, sodium compounds or other materials to the flue gas to induce the unwanted gaseous species to react with the additive and form acceptable gases or particulates that can be removed. Another technique called Selective Catalytic NOx Reduction (“SCR”) uses a catalyst to control NOx emissions. Bag houses, precipitators and even filters have been used to remove particulates from the flue gas.
Whether the use of a particular additive will be successful depends not only on the composition of the flue gas, but also the temperature of the flue gas when the additive is injected. Many materials work well only within certain temperature ranges. If that material is added while the flue gas is not within the required temperature range or if too much or too little additive is injected reactions can occur that produce undesirable compounds. These compounds can foul the precipitators, reduce the efficiency of heat exchangers and create other problems.
Ammonia (NH3) is in common use today as a reactant for the removal of nitrogen oxides from gas streams. But the NH3 also reacts with sulfur trioxide (SO3) to form ammonium sulfate ((NH4)2 SO4) or ammonium bisulfate ((NH4)HSO4 They both can plug catalytic passages of the SCR or heat transfer devices especially the regenerative air heater, which has many small passages. This plugging can restrict the flow of the air and the flue gas so severely that the boiler must be taken off-line and the air heater cleaned. The ammonium bisulfate is much the worst offender of the two as it is very sticky through much of the exhaust gas temperature range.
U.S. Pat. No. 6,677,765 discloses a method of measuring ammonia in flue gas by using a cooled probe to measure conductivity (and corrosion) caused by condensed ammonium bisulfate. This method uses a tubular probe having spaced-apart bands or patches of the same material as the probe body. The bands or patches are attached to the probe body by an electrically insulating, high temperature material. At least one thermocouple is attached to the probe. A series of cooling tubes are provided within the probe body to direct cold air to the regions near each band. One or more probes are placed in the furnace or boiler above the ammonia injection zone. When ammonium bisulfate forms on the probe it completes an electrical circuit between the probe body and the bands. Hence, the presence of ammonium bisulfate can be detected by a change in resistance between the bands and the probe body. The ammonium bisulfate will also cause corrosion of the probe. Electrochemical noise is generated during the corrosion process. A monitor connected to the probe body can detect any change in resistance as well as electrochemical noise. Furthermore, a corrosion rate can be determined from the level or amount of electrochemical noise that is detected.
Information obtained from the probe can be correlated with the position of the probe to identify those injectors that may be the source of the detected excess ammonia. Then the injectors can be adjusted to reduce or eliminate excess ammonia injection. During the combustion of hydrocarbon fuel in air, the oxygen in the air combines with the carbon and hydrogen in the fuel to form water and carbon dioxide. In the case of combustion of methane or natural gas, the flue-gas product is a combination of a relatively clean mixture of nitrogen and excess oxygen from the air with about 10 to 12% water and 12% carbon dioxide products of combustion.
However, in the case of coal combustion there are numerous impurities such as the most voluminous being chlorine, sulfur, fuel-bound nitrogenous compounds and ash mixed with the carbon and hydrocarbons making up the coal fuel. The products of combustion are about 6% water, 12% carbon dioxide, but now there are numerous other contaminants. The ash itself contains numerous compounds which may be metals such as sodium, calcium, magnesium, silica, alumina, iron and pyretic sulfur along with many trace elements which are considered pollutants such as mercury, lead, cadmium, arsenic and numerous others. All of these species have the opportunity to vaporize and oxidize throughout the high temperature combustion environment, with the resulting coal-fired flue-gas being much more complex than in the case of natural gas combustion.
With such complex flue-gases it has always been desirable to maintain the flue-gas temperature high enough such that water should not condense within the back passes of the boiler, breeching and chimney; because the water would cause solutions of all these myriad corrosive and ash compounds to accumulate into a messy and sticky gunk. This gunk thus fouling the flue-gas passages to such an extent that the equipment becomes inoperable. At the same time, the temperature should be as low as possible to maintain the efficiency of heat recovery from the fuel combustion. In order to maintain clean, safe and efficient power plant operation it is desirable to measure the condensation and fouling temperature characteristics of the flue-gas.
The condensation of water is greatly affected by the presence of sulfur trioxide to form sulfuric acid condensate and other more complex sulfates and sulfites. These various sulfur compounds all condense at temperatures much higher than the condensate temperature of pure water and include ammonium sulfate, ammonium-bi-sulfate and the sulfates and bi-sulfates of the different metal contaminants such as sodium (sodium bi-sulfate, sodium bi-sulfite, and sodium sulfate), magnesium, calcium and others.
Thus, while it is desirable operate at the lowest possible stack temperatures, to improve efficiency for lower carbon dioxide generation; at the same time, extensive use of scrubbers allows higher sulfur coal use. The sulfur and thus sulfur trioxide in the back-pass of the boilers has thus tended to increase. When coal sulfur increases the sulfur trioxide also increases but this has been greatly aggravated by the use of Selective Catalytic NOx Reduction (SCR) which further catalyzes the sulfur trioxide formation. The complexity is increased with use of ammonia injection for both SCR and Selective non-Catalytic Reduction of NOx (SNCR), because any ammonia-slip will react with sulfur trioxide to form ammonium-bisulfate which increases water condensation and fouling temperature. Beyond the back-end fouling problem, sulfur trioxide emissions from the stack cause plume visibility and pollution problems.
Given the problems of trying to operate the back-end passes, breeching and chimney at as low a temperature as possible, while not fouling; it has come to pass that attempts to remove the sulfur trioxide are being tested and employed. Remedial reagents injected at points A, B, C and D of the furnaces, shown in FIGS. 1 and 2, while reducing sulfur trioxide, exhibit their own complex condensation and decomposition characteristics and add to the amount of ash which can potentially foul the equipment.
In order to operate within the complexity described here it would be desirable to measure sulfur trioxide and its concentration dependent sulfuric acid condensation temperature if, when and where it exists by itself. But as described here it often occurs in combination with ammonia or remedial reagents and thus cannot be measured as sulfuric acid because it may take a different form as it condenses. For example ammonium-bi-sulfate condenses at 30 to 100° F. higher temperature than SO3 and thus masks the SO3 dew-point with already condensed material as the dew-point is searched for.
At temperatures above 400° F., sulfur trioxide exists in dynamic equilibrium with water and sulfuric acid molecules; while to further complicate its measurement at lower temperatures it may be adsorbed in particulate and/or aerosol form. Below 400° F. the measured dew point of sulfuric acid is the measure of total sulfur trioxide; while above that temperature the total sulfur trioxide can be calculated from the equilibrium curve. However since SO3, H2SO4, and condensed phase (aerosol and particulate) can be present, it is sometimes required to convert all forms into the condensable form of sulfuric acid below 400° F. These forms can be distinguished by filtration, and heating or cooling and denitrification of the sampled flue gas.
The sulfuric acid may still condense in the range of 250° F. to 290° F. but in the presence of ammonium-bi-sulfate or sodium-bi-sulfate condensation within the flue-gas may begin at temperatures above 320° F. and even to 600° F. Thus, a standard sulfuric acid dew-point instrument will become confused by a whole range of condensation phenomena in the complex flue-gas, when attempting to measure a specific sulfuric acid dew-point. For example, when present, the sodium-bi-sulfate will condense at temperatures above 350° F.; in that case it is necessary to use a clean cold probe to measure opposing rates of condensation and evaporation as the clean probe is heated from the bottom up of the probe heating cycle.
Consequently, there is a need for a method and probe that can accurately determine the amount of sulfur trioxide and other condensables in flue gas as well as any other gas containing condensable species.